EP3052906B1 - Méthode et appareil de mesure de composants individuels d'un fluide polyphasique - Google Patents

Méthode et appareil de mesure de composants individuels d'un fluide polyphasique Download PDF

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EP3052906B1
EP3052906B1 EP14850813.8A EP14850813A EP3052906B1 EP 3052906 B1 EP3052906 B1 EP 3052906B1 EP 14850813 A EP14850813 A EP 14850813A EP 3052906 B1 EP3052906 B1 EP 3052906B1
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Prior art keywords
multiphase
oil
reynolds number
pipe
flow
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EP3052906A4 (fr
EP3052906A1 (fr
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Arnstein Wee
Kenneth GUNDERSEN
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FMC Kongsberg Subsea AS
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FMC Kongsberg Subsea AS
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/74—Devices for measuring flow of a fluid or flow of a fluent solid material in suspension in another fluid
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/05—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects
    • G01F1/34—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects by measuring pressure or differential pressure
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/05—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects
    • G01F1/34—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects by measuring pressure or differential pressure
    • G01F1/50—Correcting or compensating means
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/05—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects
    • G01F1/34—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects by measuring pressure or differential pressure
    • G01F1/36—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using mechanical effects by measuring pressure or differential pressure the pressure or differential pressure being created by the use of flow constriction
    • G01F1/40—Details of construction of the flow constriction devices
    • G01F1/44—Venturi tubes

Definitions

  • the present invention relates to a method and flow meter for determining the flow rates of individual components of a multiphase fluid, as defined in the preambles of claims 1 and 8 respectively.
  • a flowing mixture of oil, water and gas is a common occurrence in the oil industry being a product of an unprocessed well stream.
  • a well stream is often referred to as a multiphase mixture where oil, water and gas are referred to as individual phases or fractions.
  • the amount of gas (GVF) is greater than 90% of the total volume in the pipe, the well is often referred to as a wetgas well.
  • multiphase flow in the context of this patent application covers the full component fraction range and hence includes both wetgas and multiphase flow conditions.
  • the oil wells can also be classified as light or heavy oil.
  • a condensate is a very light oil where the density typically is less than 700 kg/m3 and the viscosity typically is less than 1 cP.
  • a light crude oil typical has a density in the range 700-900 kg/m3 and a viscosity in the range 1-100 cP.
  • a heavy oil is more viscous and has a higher density.
  • Typical viscosity range is 100 - 10.000 cP and density in the range 850-1200 kg/m3. Water typically has a density in the range 1000-1200 kg/m3 with a viscosity in the range 0.5 - 2 cP.
  • test separators are expensive, occupy valuable space on a production platform, and require a long time to monitor each well because of the stabilized flow conditions required.
  • test separators are only moderately accurate (typically ⁇ 5 to 10 % of each phase flow rate) and cannot be used for continuous well monitoring.
  • Most separators use the density difference between oil, water and gas to separate the three phases, either by using the earth gravity in a tank or by using a cyclone principle. These techniques are well known.
  • a three-phase flow meter could be used in the first instance instead of a test separator and in the long term as a permanent installation on each well.
  • Such instruments need to be reasonably accurate (typically better than ⁇ 5 % of rate for each phase), non-intrusive, reliable, flow regime independent and provide accurate measurements over the full component fraction range.
  • Such an arrangement would save the loss in production normally associated with well testing. Such loss is estimated to be approximately 2% for a typical offshore installation.
  • Allocation metering is needed when a common pipeline is used to transport the output from a number of wells owned by different companies to a processing facility. This is currently achieved by passing the output of each well through a test separator before entering the common pipeline.
  • dedicated test pipelines to each well are also required.
  • a permanently installed three-phase flow meter would offer significant advantages for allocation metering.
  • a venturi tube, dall tube, orifice plate and v-cone are examples of a structure where the pipe diameter is gradually reduced into a section of the pipe with a smaller diameter. The smaller section may be short or a relative long section. For a venturi, the diameter is gradually expanded to the original size of the pipe whereas the dall tube and orifice plate has a more abrubt transition after the narrow section.
  • Mass flow measurements with such structures are well known and described in standards, patents and other publications.
  • One such standard is the ISO standard 5167 "Measurement of fluid flow by means of pressure differential devices inserted in circular cross-section conduits running full" part 1 - general principles and part 4 - venturi tubes.
  • venturi tubes for multiphase and wetgas flow conditions are further described in " Design of a flow metering process for two-phase dispersed flows", Int. J. Multiphase Flow vol 22, No 4, pp 713-732 , " A study of the performance of Venturi meters in multiphase flow", by Hall, Reader-Harris, and Millington, 2nd North American Conference on Multiphase Technology and " Liquid Correction of Venturi Meter Readings in Wet Gas Flow", by Rick de Leeuw, North Sea Flow Measurement Workshop - 1997 .
  • the discharge coefficient C is a calibration constant for the venturi, which can be found either by calibrating the venturi on a fluid such as water, oil or gas or calculated based on the mechanical dimensions and properties of the venturi. These techniques are well known and not described any further.
  • the discharge coefficient for all devices based on measurement of differential pressure across a restriction in the pipe is a function of the Reynolds number of the multiphase fluid (e.g. SPE 63118 - Qualification of a Nonintrusive Multiphase Flow Meter in Viscous Flow by D.I Atkinson et al (2000 ) - figure 5 ).
  • the Reynolds number (Re) is a dimensionless number that gives a measure of the ratio of inertial forces to viscous forces and consequently quantifies the relative importance of these two types of forces for given flow conditions.
  • venturi is used as an example.
  • differential based flow devices such as a V-cone, Dall Tube and Orifice Plate.
  • the discharge coefficient is typical in the range 0.98 - 1.0.
  • a fixed discharge coefficient in the range 0.98 - 1.0 can easily be used for the venturi without introducing any significant errors in the calculation of the flow rates.
  • the Reynolds number could be reduced such that the venturi operates in an area where the discharge coefficient is significantly lower than 1.0 and also varies with the Reynolds number.
  • Figure 10 shows examples of how the venturi discharge coefficient (20/22) changes as a function of the Reynolds number (21). From figure 10 it is seen that the discharge coefficient for this particularly venturi changes from 0.6 to 1.0 when the Reynolds number changes from 70 to 1.000.000. For heavy oil applications the Reynolds number may be below 10 giving a venturi discharge coefficient in the range 0.2 - 0.3.
  • any multiphase meter which uses a differential pressure based device to determine the flow rate of the multiphase fluid mixture, needs to determine the Reynolds number of the multiphase fluid in order to provide reliable measurement of the flow rate. This is particularly important for heavy oil applications since the variation in the Reynolds number then is significant. See for example: Miller et al.:"The Influence of Liquid Viscosity on Multiphase Flow Meters", 4th-6th March 2009, 8th International South East Asia Hydrocarbon Flow Measurement .
  • the first category is methods/devices that covers oil continuous flow conditions only
  • a second category are methods/devices that covers water continuous conditions only
  • a third category are methods that covers both oil and water continuous flow conditions.
  • Oil continuous conditions means that the water is dispersed in the oil as droplets such that oil becomes the continuous medium in the liquid phase.
  • the liquid may be dispersed as droplets in the gas or the gas may be dispersed as bubbles in the liquid phase; however, the liquid in the above example is still oil continuous.
  • the liquid is water continuous when the oil is dispersed as droplets in the water phase.
  • a water/oil mixture is also commonly referred to as an emulsion and similarly the emulsion may be either oil or water continuous.
  • For each category there may also be several sub categories such as tomographic / non-tomographic methods and devices, and intrusive / non-intrusive methods and devices etc.
  • the water cut, or water liquid ratio is defined as the amount of water (percentage) in the liquid emulsion (e.g. oil+water) of a multiphase mixture (e.g. oil + water + gas).
  • WLRs below 20% the liquid emulsion is in general oil continuous and similarly for WLRs above 80 %, the liquid emulsion is normally water continuous.
  • the liquid emulsion can be either water continuous or oil continuous. This region is commonly referred to as the switching region since the liquid may change from oil continuous to water continuous or vice versa.
  • Light crude oil typical has a switching region for WLRs in the range from 35% to 70 % whereas heavy oil or viscous oils typical have a switching region from in the WLR range from 20% to 80%.
  • the liquid phase has quite different characteristics depending whatever the liquid emulsion type is oil or water continuous. If the water is saline, an oil continuous emulsion is non-conducting whereas a water continuous emulsion is conductive. If the water is fresh there is no significant difference in the conductivity of the emulsion; however, the dielectric constant of the emulsion is quite different in the two cases irrespective of the salinity of the water as shown in figure 9 .
  • the dielectric constant of an oil continuous emulsion 18 is plotted in figure 9 for a water liquid ratio of 0 - 100% on the same graph as the dielectric constant of a water continuous emulsion 16 using the Bruggeman mixing law as described in " Electromagnetic mixing formulas and applications - IEE Electromagnetic Wave Series 47" by Ari Shivola for calculating the dielectric constant of the emulsion.
  • the oil has a dielectric constant of 2.0 and water has a dielectric constant of 80 (fresh water).
  • the relative difference is particularly large in the switching region indicated with an arrow 13.
  • the viscosity of the liquid emulsion also has a similar behavior as shown in figure 8 .
  • the viscosity of an oil continuous emulsion 15 is plotted as a function of WLR on the same graph as the viscosity of a water continuous liquid emulsion 13.
  • the viscosity of an oil/water emulsion is calculated as described in " A study of the performance of Venturi meters in multiphase flow", by Hall, Reader-Harris, and Millington, 2nd North American Conference on Multiphase Technology . In this example an oil viscosity of 20 cP (typical light oil) and a water viscosity of 1.5 cP (saline water) are used.
  • the liquid emulsion viscosity is in the range 0.01 - 0.025 Pa ⁇ s (10-25 cP) when the water fraction changes from 0 - 40 %.
  • the liquid viscosity is in the range 0.04 - 0.07 Pa ⁇ s (40-70 cP) when the water fraction is in the range 0 - 40%.
  • a change in temperature of 25°C changes the liquid viscosity by 180% in this case.
  • oil viscosity in order to be able to calculate the liquid viscosity of an oil/water emulsion, it is important to know the oil viscosity and the water viscosity in addition to the emulsion type (oil or water continuous). Since the oil viscosity is also a function of the temperature, it is also important to know how the oil viscosity changes as a function of temperature. In addition, it is also necessary to know how the amount of water modifies the viscosity of an oil continuous emulsion.
  • the viscosity difference between an oil and water continuous emulsion is particularly large for heavy oil conditions, where the viscosity for an oil continuous emulsion may be in the range 3.000 - 10.000 cP, whereas the viscosity of a water continuous emulsion may be less than 2 cP.
  • the oil viscosity may change over time and is also difficult to predict as a function of temperature.
  • a differential pressure device such as a venturi
  • WLR differential pressure device
  • One way to identify whether the emulsion is oil or water continuous is to perform laboratory experiments with particular oil and water for the field, in order to determine when the oil/water mixture changes from oil to water continuous and vice versa as a function of the measured average WLR.
  • the problem with this method is that the WLR limit for change to oil and water continuous, and vice versa, will be highly temperature and flow rate dependent, and field experience with multiphase meters have shown that it is not practical to use such a method since the WLR range for switching between oil and water continuous will contain large variations even if the average WLR is known.
  • the present invention overcomes this weakness with existing multiphase flow meters which are based on a venturi or other differential pressure device (such as a V-cone or Dall Tube) for determining the mass and volume flow rate.
  • the present invention performs a dedicated measurement in order to determine the Reynolds number of the multiphase mixture. The measured Reynolds number is then used to calculate the correct discharge coefficient for a differential pressure based flow meter such as a Venturi, V-cone, Wedge meter or Dall Tube.
  • the invention can be used in combination with any differential based multiphase flow meter such that the multiphase meter can obtain a correct discharge coefficient despite large variation in Reynolds number caused changes in the oil viscosity, WLR or emulsion type.
  • an emulsion classification measurement can also be used in order to determine the oil viscosity.
  • the oil viscosity can be calculated provided that the emulsion type is oil continuous. This is possible since the Reynolds number is highly dependent on the oil viscosity for an oil continuous liquid emulsion whereas the oil viscosity virtually has no impact on the Reynolds number when the emulsion is water continuous. Hence, for an oil continuous emulsion, the oil viscosity can be determined. Oil-fields which are producing heavy oil frequently use a light oil (called diluent) to reduce the viscosity of the oil.
  • diluent light oil
  • the diluent is mixed with the heavy oil in the reservoir to make it easier to produce the oil (a light oil with low viscosity is easier to produce compared to a heavy oil).
  • the diluent typical has a very low viscosity (less than 10 cP) whereas the heavy oil typically has a high viscosity (> 1000 cP).
  • this information can then be used to determine the ratio between reservoir oil and diluent oil which is an important control parameter in order to optimize production and recovery for heavy oil fields.
  • Multiphase flow meter which uses a differential pressure device to determine the flow rate are well known in prior art. Examples of such devices can be found in US 4638672 , US 4974452 , US 6332111 , US 6335959 , US 6378380 , US 6755086 , US 6898986 , US 6993979 , US 5135684 , US6935189 , US7624652 , WO 00/45133 , WO03/034051 , WO 02/44664 .
  • Devices for measurement of fluid viscosity and/or Reynolds number are also commonly known. Examples of such devices are found in US 8353220 and US 5661232 , based on a coriolis type flow meter. Another commonly used device for performing viscosity measurement are devices based on a vibrating element which is inserted into the flow. Examples of such devices can be found in US 8316722 and US 7325461 , which are based on electronic driven vibrating measurement transducers. Yet another type is based on vortex sensors such as US 8161801 .
  • Viscosity sensors based on coriolis type flow meter and mechanical vibrating elements are not suited for measurement of the liquid viscosity of multiphase fluids containing gas since the gas will have a large impact on the mechanical resonance frequency and may even prevent the mechanical device from resonating.
  • Coriolis type flow meters and vibrating elements are also known to be fragile devices which are not well suited for the harsh environment in an unprocessed well stream of oil, water and gas. Unprocessed well stream may also contain sand which can cause damage to intrusive devices such as a vibrating mechanical element or vortex sensor.
  • a vibrating element could be used in connection with a multiphase meter if it is installed in such a way that the gas content around the vibrating element is close to zero.
  • the gas content may be low enough for performing reliable measurements.
  • the fluid in the blind Tee may not be representative for the liquid in the pipe and hence the viscosity measurement will contain a large uncertainty if there is variation in the liquid phase (e.g. variation in the WLR or oil type). It is the purpose of this invention to overcome the above mentioned limitations of existing solutions.
  • the apparatus according to the invention is further characterized by the features as defined in the independent claim 8.
  • the present invention is based on measurement of the Reynolds number based on measurement of the pressure drop across the longitudinal part of a pipe section with known wall roughness, typically larger than the roughness of the surrounding pipe work including the multiphase meter.
  • the wall roughness should be large enough such that the flow is turbulent even for low Reynolds numbers.
  • a wall roughness greater than 0.05 is sufficient for most applications.
  • the wall roughness is here defined as the roughness of pipe wall relative to the pipe diameter.
  • the velocity and density of the multiphase fluid is determined by a multiphase flow meter.
  • a multiphase flow meter based on a differential pressure flow device is particularly suited for this invention since the Reynolds number is needed for these devices in order to determine discharge coefficient of the flow meter.
  • Example of dP based multiphase flow meters are Venturi, Dall Tube, V-Cone , Wegde and Orifice.
  • a multiphase meter is also suited to measure the fractions of the multiphase mixture.
  • the multiphase meter may be based on a tomographic measurement principle where the liquid distribution in the pipe cross section also can be determined or it may be based on non-tomographic measurement principle assuming that the multiphase mixture is evenly distributed in the cross section of the pipe.
  • Example of a tomographic measurement principle which can be used to determine the velocity and density is disclosed in US 7624652 .
  • the most common multiphase meters assume a homogeneous mixture of oil, water and gas in the cross section of the pipe.
  • a multi-component mixture of three components such as gas, water and crude oil
  • Examples of combinations suited for measurement of fractions of a multiphase mixture are permittivity measurement in combination with density measurement, conductivity measurement in combination with density measurement or two mass absorption measurements at two different energy levels.
  • the permittivity measurement may be based on any known principle. The most common one are either based on microwave sensor principles or capacitance sensor principles.
  • the corresponding physical properties for each of the components needs to be known.
  • permittivity and density measurement are used to measure the permittivity and density of a multiphase mixture containing gas, water and oil
  • the permittivity and density of the gas, water and oil needs to be known in order to calculate the volume fractions of gas, water and oil in the pipe.
  • a more correct discharge coefficient can be calculated by the multiphase meter. Based on this new value of discharge coefficient, a more correct velocity of the multiphase fluid can be determined which again can be used to calculate a more correct Reynolds number by the present invention.
  • the Reynolds number and flow rate of the multiphase mixture has then been determined. The calculation can also be performed without iteration, but then the accuracy could be reduced.
  • the WLR (water liquid ratio) of the liquid fraction is measured by the multiphase meter.
  • the oil viscosity can easily be calculated using the equation relating the liquid viscosity to the oil viscosity, water viscosity and WLR, as described in " A study of the performance of Venturi meters in multiphase flow", by Hall, Reader-Harris, and Millington, 2nd North American Conference on Multiphase Technology .
  • the effect of gas on the multiphase mixture can easily be accounted for by using the well-known Nissan-Grundberg equation, which relates the viscosity of a liquid/gas mixture to the mass fraction of the liquid and gas and the viscosity of the individual liquid and gas fractions.
  • the viscosity of the oil fraction is known, it can be used to calculate the amount of diluent injected into a heavy oil well stream, provided that the viscosity of the heavy oil and diluent is known.
  • the uniqueness of the present invention is the ability to provide a measurement of the Reynolds number of a multiphase mixture, which then can be used to correct the flow rate measurements of a multiphase flow meter in such a way that the multiphase flow meter is able to handle a large variation in liquid viscosity range which are common for heavy oil flow conditions.
  • the Reynolds number measurement is performed under stable flow conditions (i.e. measurement is performed at the same density and velocity as in the multiphase meter) and does not rely on any mechanical vibrating devices. It is known that the recovery pressure of a venturi is related to the viscosity and density of the fluid in the pipe and therefore also the Reynolds number of the flow (e.g. US 7469188 ).
  • the present invention overcomes this problem since the fluid density and fluid velocity is not changing between the Reynolds sensor and the multiphase meter, since they have the same diameter and no obstructive element between them.
  • a well defined solution for the Reynolds number is ensured by that the relationships between Reynolds number, differential pressure, and flow rate (velocity and density) are highly different.
  • friction alone generates the differential pressure, while in the venturi it is a combination of impulse and friction.
  • Yet another uniqueness of the present invention is that it works in an unprocessed well stream containing gas, water and other corrosive chemicals in addition to sand.
  • the present invention contains a tubular section 1 which contains a section with a high wall roughness 3.
  • this section is in the further description of the present invention referred to as the "Reynolds sensor”.
  • the wall of the Reynolds sensor may have "saw-teeth" pattern as shown in figure 1 , but any other mechanical design providing a rough surface, such as large threads or rectangular rings 3 as shown in figure 2 , may be used.
  • the present invention also includes a multiphase meter 2.
  • the multiphase meter may be of any type, such as those described in the previous sections, which contains a differential pressure based flow meter.
  • the multiphase flow meter described in US 7624652 is particularly suited for this purpose, and for simplicity, this flow meter is used to exemplify the invention in the description below.
  • the device or multiphase meter, also contains a temperature and pressure measurement for compensation purposes, but for simplicity these devices are omitted in the following discussions.
  • the pipe diameter of the Reynolds sensor shall have approximately the same pipe diameter as the multiphase meter as indicated by the arrow 4'. Then, the velocity of the multiphase fluid in the Reynolds sensor will be the same as the velocity in the multiphase meter as long as the Reynolds sensor is placed immediately upstream or downstream the multiphase meter.
  • Tappings (5/6) for measurement of the differential pressure are located at both ends of the Reynolds sensor.
  • a conventional differential pressure transmitter 4 can be used to measure the pressure drop across the Reynolds sensor.
  • Bernoulli's equation states that the total head h along a streamline of the pipe (parameterized by x) remains constant. This means that velocity head can be converted into gravity head and/or pressure head (or vice-versa), such that the total head h stays constant. No energy is lost in such a flow.
  • f f R e D
  • the roughness measure e is the average size of the bumps on the pipe wall.
  • the relative roughness e/D is therefore the size of the bumps compared to the diameter of the pipe. For commercial pipes this is usually a very small number. A perfectly smooth pipe would have a roughness of zero.
  • the wall roughness is large (e.g. greater than 0.05)
  • the roughness of the wall will introduce turbulence in the flow and the flow will therefore be turbulent for Reynolds numbers well below 2000.
  • the flow will also behave turbulent for very low Reynolds numbers, provided that the wall roughness is large enough.
  • the relative roughness e/D of the Reynolds sensor should be designed such that turbulent flow is obtained for the multiphase fluid conditions the sensor is intended to be used for.
  • an experimental derived curve or equation relating the Reynolds number to the friction factor can be obtained by performing flow loop experiments with the Reynolds sensors for flow conditions with known Reynolds numbers.
  • the Reynolds number of the multiphase fluid can then easily be determined by measuring the pressure at point A (5) and Point B (6) and using equation 4 to calculate the friction factor.
  • the friction factor is known, the experimentally derived relation between the friction factor and Reynolds number can be used to calculate the Reynolds number of the multiphase mixture. In the further description of the present invention, this Reynolds number is referred to as the "measured Reynolds number”.
  • an improved discharge coefficient for the venturi (or any other differential pressure based flow meter) can be calculated.
  • Figure 10 shows a plot of the venturi discharge coefficient 22 vs. Reynolds number 21 for a typical venturi.
  • the data points 20 have been obtained experimentally in a flow loop.
  • an equation relating the Venturi discharge coefficient to the measured Reynolds number can be derived.
  • This equation is then used to calculate an improved discharge coefficient based on the measured Reynolds number.
  • an improved velocity of the multiphase mixture can be calculated, which again is used to calculate an improved friction factor and improved measured Reynolds number, which again is used to calculated an improved discharge coefficient of the venturi. This calculation process is repeated until the measured Reynolds number has converged to a stable value.
  • Step 2 and 3 above can also be replaced by an iterative calculation based on equation 4 and 7, however in practice an experimental derived relationship between the friction factor and Reynolds number as described in step 2 and 3 will give the most accurate result.
  • Figure 2 shows another preferred embodiment of the present invention where the roughness of the Reynolds sensor is made of rectangular rings or grooves 3 in the wall surface.
  • the inner diameter 4' of the rectangular rings 3 is the same as the pipe diameter such that the velocity in the Reynolds sensor is the same as the velocity in the pipe.
  • FIG 4 A more practical realization of the wall roughness is shown in figure 4 where the roughness is made based on a combination of a saw-tooth pattern and rectangular rings 3. This pattern is cost efficient to fabricate in a CNC operated machining bench.
  • Another way of increasing the pressure drop across the Reynolds sensor is to let its cross-sectional shape vary between its ends, e.g. from circular through rhombic and back to circular, while maintaining a constant cross-sectional area at all points.
  • Figure 3 shows another preferred embodiment of the present invention where a second differential pressure transmitter 5' is used to measure the pressure drop across a pipe section (7/8) of the same length as the Reynolds sensor (5/6).
  • the wall roughness of this pipe section shall be low, and preferable the same value as the multiphase meter. Since the wall roughness of this section is low, the friction will also be low.
  • the algorithms for calculating the measured Reynolds number and correcting the venturi discharge coefficient will be the same as described previously, where the only modification is that the experimental curve relating the friction factor to the measured pressure drop of the Reynolds sensor will be replaced with an experimental curve relating the friction factor to the relative difference between the measurement at 4 and 5'.
  • suitable mathematical expressions for the relative difference between 4 and 5' are the ratio between 4 and 5' or the difference between 4 and 5'.
  • the present invention can also be extended with an emulsion classification measurement to determine the viscosity of the oil fraction but this extension is not part of the present invention.
  • An emulsion classification measurement is a measurement which is suited to determine whether the liquid phase is oil or water continuous. Examples of devices suited to perform emulsion classification measurement are shown in figure 5, 6 and 7 .
  • a transmitting antenna 10 and receiving antenna 11 are located in a pipe 1. The distance between the antennas 10 and 11 may be from 1 to a few pipe diameters.
  • the antennas may be of any type suited for transmitting electromagnetic energy into the pipe.
  • a coaxial antenna is common way to achieve this. Since design of antennas are well known in prior art, it is not described any further.
  • Figure 12 shows the received power 27/28 as a function of frequency 26 when the liquid phase is oil continuous
  • figure 13 shows the received power 27/28 as a function of frequency 26 when the liquid phase is water continuous.
  • the received power 27/28 is large at the highest frequency and low at the lowest frequencies.
  • the power at the highest frequencies is comparable to the power at the lowest frequencies.
  • Figure 14 shows the measured Broadband loss ratio for oil continuous emulsions 33 and water continuous emulsions 32 for WLR range of 0 - 100%.
  • the data has been obtained based on measurements in the MPM Multiphase test flow loop for a gas fraction (GVF) in the range 0 - 99.9% and water salinity in the range 0 - 1% NaCl. Since all these test points has been collected with relative low water salinity where the difference between oil continuous and water continuous is less compared to higher salinities, it is considered as being a worst-case scenario for a practical multiphase meter.
  • VMF gas fraction
  • the emulsion is classified as oil continuous if the Broadband loss ratio is below the threshold value and water continuous if the measured Broadband loss ratio is above the threshold value.
  • Figure 6 and figure 7 shows other arrangements for the transmitting and receiving antennas, but in principle the antennas may be located in any plane around the pipe circumference as long as the distance between the antennas are in the range of one to a few pipe diameters.
  • the measurement for performing the emulsion classification measurement may be obtained from a separate device/sensor. For simplicity this is not shown in any figures; however, this is considered to be obvious to a person skilled in the art. Alternatively, it may be possible to realize the emulsion classification measurement as a part of the multiphase meter 2.
  • the multiphase meter disclosed in US 7624652 is is an example of a device well suited for this purpose since it contains at least two antennas in the pipe in a similar manner as figure 5-7 .
  • the method for determining the viscosity of the oil is not part of the present invention but it can be summarized in the following steps:

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  • Fluid Mechanics (AREA)
  • General Physics & Mathematics (AREA)
  • Measuring Volume Flow (AREA)
  • Other Investigation Or Analysis Of Materials By Electrical Means (AREA)
  • Analysing Materials By The Use Of Radiation (AREA)

Claims (14)

  1. Procédé pour déterminer les débits d'un mélange à plusieurs composants dans un tuyau contenant au moins une phase liquide ayant une viscosité inconnue, le procédé comprenant les étapes suivantes:
    a. les débits des composants individuels du mélange à plusieurs composants sont mesurés dans un débitmètre à pression différentielle,
    b. le nombre de Reynolds du mélange à plusieurs composants est déterminé, et
    c. sur la base des résultats des étapes a et b, un débit plus précis des composants individuels du mélange à plusieurs composants est calculé,
    caractérisé en ce que le nombre de Reynolds est déterminé à un emplacement séparé du débitmètre où le débit du mélange à plusieurs composants est le même que dans le débitmètre.
  2. Procédé selon la revendication 1, dans lequel lesdits débits des composants individuels du mélange à plusieurs composants sont mesurés à l'aide d'un débitmètre polyphasique.
  3. Procédé selon la revendication 2, dans lequel ledit débitmètre polyphasique contient l'un parmi un tube de Venturi, un tube V-cône et un tube de Dall.
  4. Procédé selon la revendication 1, dans lequel ledit nombre de Reynolds est déterminé sur la base d'une mesure de la chute de pression à travers une section de tuyau avec une importante rugosité de paroi, de préférence supérieure à 0,05, lorsqu'elle est exprimée en tant que dimension relative par rapport au diamètre du tuyau.
  5. Procédé selon la revendication 4, dans lequel ladite section de tuyau avec une importante rugosité de paroi a le même diamètre intérieur que ledit débitmètre polyphasé.
  6. Procédé selon la revendication 4, dans lequel une section axiale à travers ladite rugosité de paroi présente l'un parmi un motif en dents de scie, un motif à onde carrée et un motif sinusoïdal.
  7. Procédé selon la revendication 1, dans lequel ledit nombre de Reynolds est déterminé sur la base d'un rapport et/ou d'une différence entre une mesure de la chute de pression à travers une section de tuyau avec une rugosité de paroi plus importante que celle de la tuyauterie environnante et la chute de pression à travers une section de tuyau avec une rugosité de paroi comme la tuyauterie environnante.
  8. Appareil pour déterminer les débits d'un mélange à plusieurs composants dans un tuyau (1) contenant au moins une phase liquide ayant une viscosité inconnue, l'appareil comprenant les éléments suivants:
    a. un débitmètre (2) à pression différentielle pour mesurer les composants individuels du mélange à plusieurs composants,
    b. des moyens (4) pour déterminer le nombre de Reynolds du mélange à plusieurs composants, et
    c. un ordinateur et un programme mathématique pour calculer le nombre de Reynolds dudit mélange à plusieurs composants et un programme mathématique pour calculer les débits des composants individuels dudit mélange à plusieurs composants,
    caractérisé en ce que les moyens (4) pour déterminer le nombre de Reynolds sont situés à un emplacement séparé du débitmètre, où le débit du mélange à plusieurs composants sera le même que dans le débitmètre.
  9. Appareil selon la revendication 8, dans lequel ledit débitmètre (2) est un débitmètre polyphasique.
  10. Appareil selon la revendication 9, dans lequel ledit débitmètre polyphasique (2) contient l'un parmi un tube de Venturi, un tube V-cône et un tube de Dall.
  11. Appareil selon la revendication 8, dans lequel lesdits moyens (4) pour déterminer le nombre de Reynolds contiennent une section de tuyau avec une importante rugosité de paroi (3), de préférence supérieure à 0,05 lorsqu'elle est exprimée en tant que dimension relative par rapport au diamètre du tuyau, et des moyens (5, 6) pour mesurer la chute de pression à travers la section de tuyau avec l'importante rugosité de paroi.
  12. Appareil selon la revendication 11, dans lequel ladite section de tuyau avec une importante rugosité de paroi (3) a le même diamètre intérieur (4') que ledit débitmètre polyphasique.
  13. Appareil selon la revendication 11, dans lequel une section axiale à travers ladite rugosité de paroi (3) présente l'un parmi un motif en dents de scie, un motif à onde carrée et un motif sinusoïdal.
  14. Appareil selon la revendication 8, dans lequel lesdit moyens (4) pour déterminer le nombre de Reynolds contient une section de tuyau avec une rugosité de paroi (3) plus importante que la tuyauterie environnante, et des moyens (5, 6) pour mesurer la chute de pression à travers la section de tuyau avec une rugosité de paroi (3) plus importante que la tuyauterie environnante et une section de tuyau avec une rugosité de paroi comme la tuyauterie environnante, et des moyens (7, 8) pour mesurer la chute de pression à travers la section de tuyau avec le rugosité du paroi comme la tuyauterie environnante.
EP14850813.8A 2013-10-01 2014-10-01 Méthode et appareil de mesure de composants individuels d'un fluide polyphasique Active EP3052906B1 (fr)

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NO20131319A NO344565B1 (no) 2013-10-01 2013-10-01 Fremgangsmåte og apparat for måling av individuelle komponenter i et flerfasefluid
PCT/NO2014/050183 WO2015050459A1 (fr) 2013-10-01 2014-10-01 Méthode et appareil de mesure de composants individuels d'un fluide polyphasique

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DE102016013220B3 (de) * 2016-11-04 2018-05-09 PROMECON Prozeß- und Meßtechnik Conrads GmbH Mikrowellenmessanordnung zur Bestimmung der Beladung einer Zweiphasenströmung
GB2558872A (en) 2016-11-11 2018-07-25 Schlumberger Technology Bv Downhole tool for measuring fluid flow
US20220373375A1 (en) * 2019-07-12 2022-11-24 Schlumberger Technology Corporation Method and apparatus for determining wlr in wet gas and multiphase flows using an electromagnetic sensor
DE102019134602A1 (de) * 2019-12-16 2021-06-17 Endress+Hauser Flowtec Ag Verfahren zum Betreiben einer Durchflussmessstelle für Medien mit zumindest einer flüssigen Phase

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NO344565B1 (no) 2020-02-03
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WO2015050459A1 (fr) 2015-04-09
US9605987B2 (en) 2017-03-28
CA2923495C (fr) 2021-06-22
EP3052906A4 (fr) 2016-10-19
BR112016007273B1 (pt) 2020-12-29
BR112016007273A2 (pt) 2017-09-12
EP3052906A1 (fr) 2016-08-10
NO20131319A1 (no) 2015-04-02

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